Inferring wellsite operations from power consumption measurements

ABSTRACT

A surface rig system includes components that consume power (e.g., using electrical motors). The power consumption of the components is monitored and used to infer other operational parameters. Illustratively, power consumption (e.g., current draw) of a shale shaker is monitored and used to infer: the volume of cuttings on the screen; changes in fluid viscosity, density, or rheology; health of the shaker screen; fluid cycle times; or screen clogging/blinding. Power consumption of pumps, fluid agitators, draw works, and other devices can also be monitored and used to infer parameters such as: fluid viscosity, density or rheology; hook load, or fluid slugging. Based on inferred parameters, changes may be made or advised for operation of equipment, including a shale shaker, downhole tool, pump, shaker screen, top drive, drilling fluid, or draw works.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to and the benefit of U.S. Patent Application No. 63/067,360, filed on Aug. 19, 2020, which is hereby incorporated by reference in its entirety.

BACKGROUND

In the wellbore construction process, the subterranean formation is broken down by a drill bit. This drilling process creates rock cuttings that are then carried to the surface by a drilling fluid that is often referred to as drilling mud. The drilling mud is then passed through sieves or screens mounted on equipment known as a shale shaker, where the rock cuttings are separated from the drilling mud. The screens on the shale shaker vibrate to improve the efficiency of the separation process. The separated rock cuttings fall over the edge of the screen into an appropriate disposal mechanism.

There are several factors that affect the size, shape, and amount of rock cuttings generated and conveyed to the surface during the wellbore construction process. These include the type and condition of drill bit used, the drilling parameters for the drilling operation (e.g., weight-on-bit (WOB), rotational speed, etc.), the compressive strengths of the rocks, and other parameters dictated by geomechanics. For instance, “caving” may also be observed during the drilling of the wellbore and refers to large rock masses that fail through naturally occurring weak planes or through the disturbance of an in-situ pressure regime that may exist within the rocks. As the drilling process alters the stress regimes of the rock, an instability in the wellbore may be triggered, thereby causing the rocks to cave in.

Some types of rocks (e.g., shale) may be sensitive to the chemical environment. For example, when the rocks contact the drilling fluid, the rocks may swell, weaken, and eventually collapse in the wellbore. Such a process may affect the volume and even the shape of some of the rock cuttings.

The configuration of the shale shakers at the surface may be varied based on the type of fluid, the volume of drill cuttings, the characteristics of the shaker screen in use, or other parameters. Adjusting the angle of the shale shaker, relative to level, may help maximize the efficiency and lifespan of the shale shaker and shaker screens. The vibration speed of the shaker screen may also be varied to optimize efficiency and the useful lifespan of a shaker screen.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to describe the manner in which the above-recited and other features of the disclosure can be obtained, a more particular description will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. While some of the drawings may be schematic or exaggerated representations of concepts, at least some of the drawings may be drawn to scale, but represent concepts that may have other dimensions or scale in other applications or conditions. Understanding that the drawings depict some example embodiments, the embodiments will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:

FIG. 1 is a schematic illustration of a wellbore drilling system, including surface systems and downhole tools used for drilling a wellbore, according to some embodiments of the present disclosure;

FIG. 2 is a schematic illustration of an analysis system, according to embodiments of the present disclosure;

FIG. 3 is a set of plots representing eight hours of drilling data, and includes plots reflective of standpipe pressure and rotational speed, rate of penetration, and cuttings flux at each of three shakers, according to embodiments of the present disclosure;

FIG. 4 is a flow chart of a method for using power consumption measurements to infer operational parameters, according to some embodiments of the present disclosure;

FIG. 5 is a flow chart of a method for calibration of power consumption to mass flow of cuttings, according to some embodiments of the present disclosure;

FIG. 6 is a flow chart of a method for controlling drilling operations, according to some embodiments of the present disclosure;

FIG. 7 is a flow chart of a method for determining a mass of wellbore cuttings, according to some embodiments of the present disclosure; and

FIG. 8 is a flow chart of a method for controlling a drilling operation, according to some embodiments of the present disclosure.

DETAILED DESCRIPTION

Embodiments of the present disclosure relate to systems, methods, and devices that evaluate the volume of drilling cuttings on a shale shaker. More particularly, aspects of the present disclosure include monitoring the power consumption (e.g., voltage, current draw, etc.) of a shale shaker in order to estimate one or more of the cuttings volume, the drilling fluid volume, or the drilling fluid viscosity.

With reference to FIG. 1, an illustrative drilling system 100 is shown, according to the present disclosure. The drilling system 100 may generate rock cuttings, such as during drilling of a wellbore used for producing a fluid such as hydrocarbons (e.g., oil, gas, etc.) or water.

The drilling system 100 can include any number of components, some of which are illustratively shown in FIG. 1, including a rotary drilling tool 102 drilling a wellbore 104 in a subsurface rock formation 105. The drilling system 100 may also include surface equipment 106 used to facilitate use of the rotary drilling tool 102. For instance, the drilling tool 102 may include a drill string 107 that includes a set of hollow pipes known as drill pipe or drill collars, and which extend to a bottomhole assembly (BHA) that includes a drill bit 108 at the lower end thereof. The drill pipe provides an internal conduit which makes it possible to bring a drilling fluid from the surface to the drill bit 108. The drilling tool 102 may therefore also include an injection head 109 screwed onto or otherwise attached to an upper portion of the drill string 107.

The surface equipment 106 may be used to attach drill pipe to the rotary drilling tool 102, and place the drill pipe into the wellbore 104 as the drill bit cuts the subsurface rock formation 105 and extends the length of the wellbore 104. The surface equipment 106 may also include a wellhead 110 having a discharge pipe 111 that closes the wellbore 104. The drilling fluid flowing through the injection head 109 and into the drill string 107 is a drilling mud, which may include a water-based or oil-based drilling mud.

The surface equipment 106 may further include a support structure 112 for supporting the drilling tool 102 and driving it in rotation, an injector or mud pit 1 for supplying and injecting the drilling fluid, and a cutting separation element, such as a shale shaker 114. The cuttings separation element may be any element that can separate cuttings from drilling flushed out of the wellbore. In some embodiments, the surface equipment 106 may include multiple separation elements. The injector/mud pit 113 is hydraulically connected to the injection head 109 in order to introduce and circulate the drilling fluid in the interior of the drill string 107. The shale shaker 114 collects the drilling fluid charged with drilling residues, known as cuttings, as the residue flows out the discharge pipe 111. The shale shaker 114 can include a vibrating screen 115 allowing the separation of the solid drilling cuttings 116 from the drilling mud. The shale shaker 114 also includes an outlet 117 for evacuating the drilling cuttings 116.

The shale shaker 114 is driven by one or more electric motors. The electric motors may cause the vibrating screen 115 to vibrate and/or oscillate. The vibrating screen 115 may be oriented at a screen angle to allow the cuttings 116 that are larger than the opening size on the vibrating screen 115 to pass out of the outlet 117. By changing the oscillation frequency, the oscillation amplitude, the screen angle, any other parameter of the shale shaker 114, and combinations thereof, the throughput of the shale shaker 114 may be adjusted. In some embodiments, the shale shaker 114 may include two or more shale shakers 114. The throughput of the shale shaker 114 may then be changed by adding or removing a shale shaker from operation to reach a desired throughput.

According to embodiments of the present disclosure, the surface equipment 106 can include an analysis device 120 used to estimate a volume and/or mass of cuttings on the shale shaker 114, such as the cuttings on the screen 115, the cuttings flowing through the outlet 117, and so forth. The analysis device 120 may include any number of types of devices, including devices that analyze the amount of power being consumed by the shale shaker 114 (e.g., the power drawn by the motors powering the vibrating screen 115), devices that measure the weight of cuttings on the screen 115 or flowing through the outlet 117, video/image based processors that visually analyze the flow of cuttings on the screen 115 or through the outlet 117, ultrasound-based processors that analyze the flow of cuttings on the screen 115 or through the outlet 117, other devices, or combinations thereof In some cases, the analysis device 120 is located on the shale shaker 114 or at or near the outlet 117; however, this is illustrative. For instance, the surface equipment 106 may include a central location where sensors provide information on power/current draw for various devices, and the analysis device 120 may be fully or partially located at, near, or even embedded within other systems that evaluate power or current requirements for other portions of the surface equipment 106.

During operation of the shale shaker 114, the motors may draw a variable amount of power, depending on the content of the material passing through the shale shaker 114. For example, a larger mass of material on the shale shaker 114 may be associated with a higher power draw on the motors, and a smaller mass of material on the shale shaker 114 may be associated with a lower power draw on the motors. In some examples, a higher viscosity fluid may have a different power draw profile than a lower viscosity fluid. In some examples, different densities of the drilling fluid and/or the cuttings may result in a different power draw profile on the motors. By analyzing the power draw profile of the motors during operation of the shale shaker 114, cuttings characteristics of the cuttings 116 may be inferred or determined. This may be a low-cost alternative to conventional sensor-based cuttings systems. Furthermore, analyzing power draw may utilize fewer processing resources than image analysis techniques.

The analysis device 120 may include a central processor or controller, or several local processors or controllers. For instance, the analysis device may be used to not only perform analysis, but automate control of a response to the results of the analysis. Examples of such responses are described in greater detail herein, but may include modifying operation of the shaker 114 (or multiple shakers 114), the mud pit/injector 113, or other components that control operation of the shaker a controller for each unit.

The analysis device 120 may therefore also include, or be coupled to, a control device 121 configured to trigger a respective device to function in a predetermined manner or sequence. The control device 121 may, for instance, take into account the state of the device it triggers, and may consider the state of one or more other devices. The state of each device may be determined via sensors such as a position sensor, weighing sensor, power/current sensor, image/video sensor, etc. The analysis device 120 or another device within the surface equipment 106 or the drilling tool 102 may also measure external parameters such as a movement of a rig platform on which the analysis device 120 is installed, power or current draw from other components (e.g., draw works, mud pumps, etc.), vibration or position (e.g., direction and inclination) of the drilling tool 102, logged measurements of the subsurface formation 105 near the drilling tool 102, or the like. The analysis device 120 may use such information in determining a condition of the shale shaker 114, including possibly correlating the drilling cuttings 116 currently on the shale shaker 114 with a strata or other feature of the subsurface rock formation 105.

The control device 121 may control one or more surface or downhole parameters. For example, the control device 121 may control one or more surface or downhole parameters based on the inferred or determined mass of cuttings 116 separated by the shale shaker(s) 114. In some embodiments, controlling the surface and/or downhole parameters may include at least one of balancing cuttings load between multiple separation elements, balancing fluid volume between multiple separation elements, balancing power consumption between multiple separation elements, changing an oscillation of the separation element, changing a screen angle of the separation element, fluid flushing a screen of the separation elements, changing weight-on-bit, changing rotational speed, changing fluid flow rate, changing fluid density, changing drill pipe acceleration or deceleration during tripping, diverting fluid from the separation element, changing a fluid treatment plan, or generating an alarm. Using the power draw from the shale shaker(s) 114 may allow a drilling operator to quickly and easily identify a drilling or operating state, and apply a control measure to modify the drilling or operating state.

Wellbores may be thousands of meters long, including vertical and lateral sections. In some situations, drilling fluid may take a long time (e.g., 30 minutes, 1 hour, 2 hours, or more) to circulate from the mud pit, through the drilling tool 102, into the annulus between the drilling tool 102 and the wellbore 104 wall, and back to the surface. It may be difficult to determine when all of the cuttings from a particular section of the wellbore 104 have been flushed to the surface. A drilling operator may measure the mass of the cuttings 116 that are collected by the shale shaker 114 and compare the mass of the cuttings 116 to an expected mass of cuttings for the particular section of the wellbore 104. The expected mass of cuttings may be estimated using the wellbore diameter and the section length of the section of the wellbore to determine the volume of the section of the wellbore. The volume of the section of the wellbore may then be multiplied by an anticipated density of the section of the wellbore to determine the expected mass of the cuttings. The anticipated density of the section of the wellbore may be collected from survey logs, geographical maps, geotechnical models, any other geological or geotechnical source, and combinations thereof.

In accordance with embodiments of the present disclosure, if the collected mass of cuttings 116 is approximately the same as the expected mass of the cuttings, then the drilling operator may determine that the section of the wellbore has been flushed or cleaned, and that there are not significant amounts of cuttings 116 remaining in the wellbore 104. In some embodiments, it may not be possible for the collected mass of cuttings 116 to be exactly the same as the expected mass of cuttings, due to natural variations in rock density, cuttings that small enough to pass through the openings in the vibrating screen 115, drilling fluid that coats the cuttings 116 that pass through the outlet 117, and so forth. In some embodiments, the collected mass of cuttings 116 may be approximately the same as the expected mass of the cuttings (or the mass of cuttings on a first shaker may be considered to be the same as the mass of cuttings on a second shaker) if there is a difference of less than 1%, less than 2.5%, less than 5%, less than 7.5%, less than 10%, less than 15%, less than 20%, or any value therebetween.

If the collected mass of cuttings 116 is different from the expected mass of the cuttings, or if the mass of cuttings on one shaker is different than the mass of cuttings on a second shaker, then the drilling operator may determine that a control measure may be taken. For example, if the collected mass of cuttings 116 is less than the expected mass of the cuttings, then the drilling operator may determine that the drilling fluid may be circulated for a longer period until the collected mass of cuttings 116 is approximately equal to the expected mass of the cuttings. If the mass of cuttings 116 on one shaker is different than the mass of cuttings 116 on a second shale shaker, a control measure may be taken to balance the mass of cuttings 116 on the shakers. In some embodiments, if the collected mass of the cuttings 116 is less than the expected mass of the cuttings or the mass of cuttings on another shaker, the drilling operator may then determine that a change may be made to the drilling fluid, such as an increase in drilling fluid density to help flush the cuttings 116 out of the wellbore. In some embodiments, the drilling operator may take any other control measure, such as increasing the drilling fluid volume, increasing the drilling fluid viscosity, increasing the RPM of the drilling tool 102, cleaning a shaker screen, flushing a shaker control line, routing cuttings to a different shaker, changing any other drilling parameter, or combinations thereof.

In some embodiments, if the collected mass of the cuttings 116 is greater than the expected mass of the cuttings, then the drilling operator may determine that a portion of the wellbore 104 has caved in or otherwise released material into the wellbore 104. Identifying a cave-in may help the drilling operator to reach quickly to mitigate or otherwise react to the cave-in.

The drilling system 100 is illustrative and is not intended to provide an exhaustive view of each feature that may be used on a drilling rig or other type of surface equipment. Indeed, drilling may include dozens of people performing dozens of different, but interconnected activities using different types of equipment, interfaces, and operations. Understanding the current status of ongoing activities can be of particular importance in order to provide not only efficient drilling or operations, but to protect the health and safety of those at the rig site, and to protect the environment. Consequently, thousands of sensors may actively monitor numerous operation, devices, and equipment, in addition to information about the downhole drilling environment.

Despite the multitude of sensors that are available and may be used to monitor a drilling and well construction process, it can be difficult to measure some critical process parameters. This can include, for instance, measuring the cuttings exiting the well, fluid actually being pumped at a specific time, etc. Further, by optionally applying automated, computer-based interpretation, continuous, robust, and accurate assessment of many different phenomena may potentially be achieved without requiring a person-in-the-loop, and in some cases can be used to improve safety, reduce costs, or improve efficiency.

As described herein, some embodiments of the present disclosure include monitoring the electrical power consumption being fed to a particular device within the surface equipment 106, as a proxy to characterize other parameters of interest. With reference to FIG. 2, an analysis system 220 for use in using power consumption information is schematically shown and described in some additional detail.

FIG. 2 specifically illustrates the analysis system 220 in accordance with some embodiments. The analysis system 220 may include a computer or computer system 222, which may be an individual computer system or an arrangement of distributed computer systems. In at least one embodiment, the computer system 222 may be the analysis device 120 described herein.

The computer system 222 of FIG. 2 includes one or more analysis modules 223 that are configured to perform various tasks according to some embodiments, such as one or more methods disclosed herein. To perform these various tasks, the analysis module 223 executes independently, or in coordination with, one or more processors 224, which are connected to one or more storage media 225 or memory. The processor(s) 224 are also connected to a network interface 226 to allow the computer system 222 to communicate over a data network 227 with one or more additional devices, sensor systems, computer systems, and the like (e.g., shale shaker(s) 214, mud pump(s) 228, sensor system(s) 229, flow meter(s) 230, or computer system(s) 231. Computer system(s) 231 may or may not share the same architecture as computer system 222, and may be located in different physical locations. For instance, computer system 222 may be located at the rig site, while in communication with one or more computer systems located in one or more data centers, processing centers, or located in varying countries on different continents.

A processor 224 may include a microprocessor, microcontroller, processor module or subsystem, programmable integrated circuit, programmable gate array, or another control or computing device. The storage media 225 may be implemented as one or more computer-readable or machine-readable storage media. Further, while FIG. 2 depicts storage media 225 as within the computer system 222, in some embodiments, the storage media 225 may be distributed within and/or across multiple internal or external enclosures of computing system 222 or additional computing systems (including computer systems 231 or systems 214, 228, 229, 230). Storage media 225 may include one or more different forms of memory including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories, magnetic disks such as fixed, floppy and removable disks, other magnetic media including tape, optical media such as compact disks (CDs) or digital video disks (DVDs), BLU-RAY® disks, or other types of optical storage, or other types of storage devices. Note that the instructions discussed above may be provided on one computer-readable or machine-readable storage medium, or alternatively, may be provided on multiple computer-readable or machine-readable storage media distributed in a large system having possibly plural nodes. Such computer-readable or machine-readable storage medium or media is considered to be part of an article of manufacture, which may be manufactured as a single component or as multiple components. The storage medium or media may be located either in the machine running the machine-readable instructions, or may be located at a remote site from which machine-readable instructions may be downloaded over a network for execution. The instructions, when accessed by the processor, may cause the processor to perform actions.

In some embodiments, the analysis system 220 contains one or more comparison module(s) 232. In the example of analysis system 220, computer system 222 includes the comparison module 232. In some embodiments, a single comparison module may be used to perform one or more embodiments of the methods disclosed herein. In other embodiments, a plurality of comparison modules may be used to perform the methods herein. The comparison module(s) 232 may be configured to compare power consumption of different equipment (e.g., the shale shakers 114 of FIG. 1) to balance loading, to calculate cuttings volume, to determine changes in fluid density/viscosity/rheology, or for any number of purposes or comparisons as described herein.

In some embodiments, the analysis system 220 contains one or more control module(s) 221. In the example of analysis system 220, computer system 222 includes the control module 221. In some embodiments, a single control module may be used to perform automated or other control of one or more components (e.g., shale shaker 214, mud pumps 228, sensor systems 229, flow meters 230, computing systems 231, or equipment at a rig site or related to operation of a rig, and the like).

It should be appreciated that the analysis system 220 and computer system 222 are merely examples, and that analysis system 220 and/or computing system 900 may have more or fewer components than shown, may combine additional components not depicted in the example embodiment of FIG. 2, or may have a different configuration or arrangement of the components depicted in FIG. 2. The various components shown in FIG. 2 may be implemented in hardware, software, or a combination of both hardware and software, including one or more signal processing or application specific integrated circuits. Further, methods described herein and implemented by the analysis system 220 may be implemented by running one or more functional modules in information processing apparatus such as general purpose processors or application specific chips, such as ASICs, FPGAs, PLDs, or other appropriate devices. These modules, combinations of these modules, and/or their combination with general hardware are all included within the scope of the present disclosure.

To illustrate example embodiments and aspects of the present disclosure, FIG. 3 includes a set of rig data measured over an eight-hour period, and includes plots 335, 336, and 337-1 to 337-3. In particular, plot 335 shows a plot of standpipe pressure 338 and rotational speed 339 over the drilling period, while plot 336 shows the rate-of-penetration (ROP) over the drilling period. Plots 337-1 to 337-3 are each specific to a particular shale shaker at the surface, and plot the cuttings flux or volume as measured by a weight-based cuttings flow meter 341-1, 341-2, 341-3 compared to the cuttings flux/volume measured by monitoring the electrical power consumption of the same shaker. Plot 337-1 includes only the cuttings flux/volume from a flow meter, and does not include the estimate from electrical power consumption.

In a particular embodiment, the rig including the three shakers may use a variable frequency drive (VFD) in which the measure of the current draw is an output for the motor control system. In other cases, clamp on or other low-cost devices may be used to calculate or measure the power/current. By way of illustration, the 381 Remote Display True RMS AC/DC Clamp Meter with IFLEX, available from Fluke Corporation of Everett, Wash., USA may be used for 3-phase measurements of current draw. Of course, the power consumption may also be measured or calculated in addition to, or instead of, the current draw. While embodiments of the present disclosure may discuss power draw, power consumption, or other measurements of power consumptions, it should be understood that the operating load of the shakers may be determined using any measurable metric of the motor, including current draw, voltage drop, and so forth.

From a view of plots 337-2 and 337-3, it is evident that the use of current drawn by the corresponding shale shakers can represent the parameter for the flux of cuttings obtained from the wellbore. Although the power-based measurement 342-2, 342-3 as calibrated in the plots 337-2 and 337-3 may not have the same accuracy as the cuttings flow meter measurements 341-2, 341-3, the plots offer a qualitative view of the cuttings flux, and the cost for obtaining the measurement may be orders of magnitude (e.g., two or more) less than the cost to obtain the cuttings flow meter measurements.

FIG. 4 is a flow chart of a method 467 for inferring cuttings properties from a wellbore, according to at least one embodiment of the present disclosure. The method 467 includes performing a drilling operation at 459. As discussed herein, the drilling operation may be any drilling operation. For example, the drilling operation may be eroding formation or other wellbore structures using a cutting element connected to a downhole tool, such as a bit, a reamer, a casing cutter, and so forth. As cuttings are flushed out of the wellbore using drilling fluid, the cuttings are separated from the drilling fluid using a separation element, such as a shale shaker at 461. The power consumption of the separation may be monitored at 463, and one or more properties of the cuttings may be inferred at 465. For example, the mass flow rate, density, particle size, and so forth of the cuttings may be inferred from the power consumption of the separation element.

Turning now to FIG. 5, an example method 550 is shown for estimating cuttings flux/volume from shale shaker power consumed. According to the illustrated embodiment, an initial calibration 551 may be performed for converting power consumption measurements into cuttings flux/volume measurements at a shale shaker, as will be discussed further herein with reference to FIG. 6.

When the calibration model is developed at 551, the cuttings volume/flux may be estimated. This may include, for instance, measuring the power consumption of one or more shale shakers at 552. As discussed herein, the raw (e.g., directly measured) or derived power or current draw may be used in some embodiments. Using the power consumption and the calibration model, the cuttings flux/volume at the shale shaker may be estimated at 553.

Having the ability to continuously monitor the load on individual shakers can be used to provide various additional features. For instance, the drill rig shown in FIG. 3 has three shale shakers. On a drill rig having two or more shakers, the work done by the shakers may not be equal. For example, at drilling period 344 of FIG. 3 which occurs leading into the fourth hour of drilling (hour 44 in the plot), the first and third shakers (plots 337-1, 337-3) increase in cuttings loading, while cuttings flux drops at the second shaker (plot 337-2). Knowing the difference in cuttings loading at the different shakers can be used to load balance the work done by shakers. Thus, the method 550 of FIG. 5 may therefore include controlling operations based on the cuttings flux/volume estimation at 554.

For example, controlling operations at 554 may include comparing a first wellbore mass or mass flow of wellbore cuttings on a first shale shaker to a second wellbore mass or mass flow of wellbore cuttings on a second shale shaker. If the first wellbore mass is different from the second wellbore mass, the first and second shale shakers may not be balanced. A drilling operator or technician may apply a control measure to balance the first and second shale shakers. For instance, the drilling operator may change one or more of the input lines, valves, may unclog an input line, clean or replace a shaker screen, take one shaker offline and replace it with a third shaker, or perform any other control measure to balance the mass flow of wellb ore cuttings across the first shale shaker, the second shale shaker, or any number of additional shakers.

In comparing the difference in the first and second wellbore masses, the control measure may be applied if there is any difference; however, in practice determining when the first wellbore mass is different from the second wellbore mass may include applying a tolerance. For instance, the first and second wellbore masses may be considered to be the same when there is a difference of less than 1%, less than 2.5%, less than 5%, less than 7.5%, less than 10%, less than 15%, less than 20%, less than 25%, less than 35%, or any value therebetween.

In the case of load balancing on shakers, the power data may be used to control fluid flow and manage how fluid returning from the well is distributed to the shakers. For instance, slough gates or other shared feed trough may be automatically adjusted based on the difference in estimated cuttings (and difference in power consumption indicative of cuttings volume), to balance the flow. In other cases, controlling the operations at 554 may include generating an instruction or notice to an operator to manually adjust slough gates or other shared feed trough or flow control devices. In some cases, the power consumption may be used to identify one shaker is receiving more cuttings than others, which may be representative of a plumbing/blockage that can then be controlled or otherwise remediated (e.g., by jetting, manual intervention, etc.).

Accordingly, the power consumption measurements at 552 can enable the distribution of load to be identified and either controlled electronically (optionally without a quantitative analysis and instead using a qualitative analysis between shakers), or to be used to approximate the likely size of the beach end/head of the fluid on the screens, which is a feature of shaker performance that otherwise is performed manually. With accurate power consumption monitoring, settings like oscillation rate, power draw, and operational mode could be modified/controlled automatically at 554 upon load increases. For instance, the information would be usable to determine when to transition the shaker boosted rates instead of default rates. Such a transition may currently be based on an operator's judgement, and if too late or too constant, can damage the shaker equipment.

In some embodiments, the power consumption may be used as a proxy measurement of how well the corresponding shaker is coping with the volume of fluid and cuttings it is receiving (e.g., high power consumption relates to high volume of fluid and cuttings). In such a case, the estimated cuttings volume/flux may be high and could indicate the shaker is likely to overflow, flood, or be blinded. When the shaker is determined to be overflowing, flooded, blinded, or otherwise overloaded based on shaker power consumption at 553 (or overloaded in comparison to other shakers which may have a smaller power consumption whether or not the cuttings loading is the same, higher, or lower), controlling operations at 554 of FIG. 5 may include automatically controlling an angle of the shaker (e.g., an angle of the vibrating screen or other element of the shaker) to improve shaker performance, or distributing the fluid to other shakers as described herein. In some embodiments, controlling operations at 554 may include automatically activating a jetting system that sprays water, oil, air, or some other fluid at the shaker screen, and which cleans the shaker. Such controls may be used, for instance, to reduce overflowing, blinding, flooding, and the like on one shaker (or on multiple shakers), particularly including in combination with balancing load to another shaker that is underutilized in terms of volume or power consumption. This may also have benefits for balancing screen wear on the shakers. In still other embodiments, controlling operations at 554 may include reducing WOB, rotational speed, or other parameters to reduce downhole generation of cuttings (i.e., ROP).

Controlling operations based on cuttings flux/volume at 554 may also include optimizing shaker operating configuration and the speed/acceleration that uses the measured power consumption. For instance, the vibration profile (amplitude, period/frequency, etc.) may be automatically modified. This may be used to obtain better solids removal efficiency, lower overall energy use of the shaker, or increase life of consumable screens. For instance, if the power consumption indicates that cuttings volume is low, the power directed to vibrating the screen may be reduced.

In some embodiments, the power draw profile (e.g., the high frequency pattern of the power draw) may allow a drilling operator to determine or infer information about the operation of the shale shakers. For example, a particular power draw profile may be associated with a particular fluid density, a change in fluid density, a cuttings density, a change in cuttings density, and so forth. In some embodiments, by analyzing changes in the power draw profile, a drilling operator may determine whether there has been a change in the drilling fluid and/or cuttings. For example, to change the density and/or viscosity of the drilling fluid, a drilling operator may add an additive to the drilling fluid before it enters the drill string. The drilling operator may then observe the change in the power draw profile to determine when the altered drilling fluid returns to the surface. This may help the drilling operator to determine or approximate the total amount of time that it takes for drilling fluid to circulate through the wellbore. In some examples, the drilling operator may know or infer, through directional drilling measurements or other measurements, when the drill bit has drilled through a change in formation and/or formation type. The change in formation may be associated with a change in rock density. By analyzing changes in the power draw profile, the drilling operator may determine when the cuttings from the change in formation have arrived at the surface. This may help to understand how long it takes to flush cuttings from the end of the wellbore to the surface and/or provide verification to the change in formation. Furthermore, this may help to identify previously unknown or unanticipated changes in formation, rock type, rock quality, or other unanticipated changed in rock.

In a system where there are multiple shakers, estimating the cuttings flux/volume at 553 may include estimating the difference or split of cuttings flow between multiple shakers. In some cases, the split of flow may be known, and the power consumption measured at 552 or the estimated cuttings flux at 553 may be compared to the known split of flow. This may be used, for instance, to determine shaker efficiency and monitor changes in conditions of the shakers. According to some embodiments, monitoring efficiency and condition changes can allow implementation of an optimization strategy where individual shakers can be tuned (e.g., by performing preventative maintenance, changing screen type/parameters, etc.) relative to other shakers.

In some embodiments, estimating the cuttings flux/volume at 553 may occur over a period of time. The cuttings from the wellbore are not flushed to the surface all at once, but rather are flushed to the surface over a period of time. Analyzing and/or tracking the mass flow of the cuttings over a period of time, the drilling operator may help the drilling operator to identify and/or analyze patterns in the mass flow of the cuttings. For example, the drilling operator may determine a cumulative collected mass of wellbore cuttings (e.g., a wellbore mass of the wellbore cuttings) or a measured cuttings mass over the time period. The cumulative mass of wellbore cuttings collected over the time period may help the drilling operator to compare with an expected mass of cuttings (determined using the geometry of the borehole, the depth drilled, and the formation or rock type being drilled through). If the cumulative collected mass of wellbore cuttings is different from the expected mass of cuttings, then the drilling operator may determine whether to perform a control measure.

In some embodiments, analyzing and/or tracking the mass flow of cuttings over a period of time may help to identify patterns in the mass flow. For example, the drilling operator may determine trends, such as changes in rock type, changes in the mass flow rate, indications of a blockage, indications of a blockage that is broken up or dislodged, changes in cutting size, a reduction in cuttings associated with cleaning the borehole, cave-ins in the borehole, any other trends, and combinations thereof. As discussed herein, power meters are relatively cheap, and therefore analyzing the power draw of the shale shakers may provide the drilling operator with a quick and cheap mechanism to determine patterns and/or changes in drilling conditions.

According to another embodiment, the circulating pressure and the pump power demand may be monitored. In general, the pressure and power demand would increase as weighted or higher viscosity fluid is used and passed through the drill bit. The higher viscosity fluid may also carry more cuttings to surface, and the increase in cuttings can be monitored as the fluid returns to surface by monitoring the shaker power at 552 and estimating cuttings flux/volume at 553. This may open up additional opportunities for state estimation and circulating system optimization, including the ability to estimate the actual sweep effectiveness of the fluid selection, and then potentially select/control operations by selecting a more optimal fluid.

In some embodiments, estimating the cuttings flux/volume based on power consumption may sometimes include a further process of cross-calibrating the estimate at 555. For instance, rig or other surface equipment may include multiple components that may be used for estimating or measuring shaker load. For instance, one or more shakers may be monitored by an image/video analysis system that may be used as a computer vision system (e.g., a cuttings volume machine vision system) to detect the quantity, type, shape, etc. of cuttings on a shaker screen. Examples of some such computer vision systems are described in U.S. Publication No. 2016/0130928, U.S. Publication No. 2017/0058620 and U.S. Publication No. 2017/0161885, the disclosures of which are incorporated herein by this reference in their entireties. In other cases, a cuttings flow meter such as that described herein and which measures the weight of cuttings may be used. An example of such a system is the CLEAR hole cleaning tools and service offered by Schlumberger Limited. In some embodiments, rather than running secondary systems all the time (whether on all shakers or on a single shaker or fewer than all shakers), the secondary systems may be run intermittently. When run, such systems may be used in the cross-calibration at 555 to verify and refine the model, but intermittent use can reduce operating costs while power consumption monitoring may be continuous. Of course, the cross-calibration performed at 555 may also generate a refined model that may be used as part of the calibration at 551 and used in subsequent instances where power consumption is measured and monitored at 552.

FIG. 6 is a representation of a method 666 for calibration of power consumption to mass flow of cuttings, according to at least one embodiment of the present disclosure. The method 666 may be performed in any number of manners. In the embodiment shown, the calibration includes measuring a base power consumption of the shale shaker at 658. The base power consumption of the shale shaker may be measured in different ways. For example, the power consumption of the shale shaker may be measured by vibrating the vibrating screen without any load on the vibrating screen and measuring the associated power consumption.

In some embodiments, the power consumption of the vibrating screen may then be measured while loaded while also obtaining measurements of a known mass and/or a known mass flow rate and/or a known drilling fluid density from a cuttings flow meter based on measured weight of cuttings at 660. The known mass and/or known mass flow rate may be measured using a mass-based cuttings flow meter at an outlet of the shale shaker. Using these collected measurements, a relationship between the power consumption and the mass flow rate may be determined at 662. For example, the current/power measurement may be converted to a cuttings flux/volume/weight measurement. The calibration may include any suitable technique, and in some cases may include using a machine learning or data analytics approach to develop a calibration model. Further, if multiple shakers are used, the calibration model may be a consistent model for all shakers, or individual calibration models may be used for each shaker. In some embodiments, the calibration may also include calibrating power consumption against unloaded power consumption, calibration using a machine vision system, or the like. Calibration may also include or be updated by cross-calibration as discussed in more detail herein.

In some embodiments, the calibration may take into account additional or other factors besides power/current and volume/flux measured by another device. For instance, the plots in FIG. 3 show a drilling period 343 at the second hour of drilling (shown in the plots as hour 42) where the estimated cuttings flux based on power consumption appear to deviate from the measurements from the cuttings flow meter. Also of interest, and as shown in plot 335, is that during this same period, the rotational speed 339 dropped relative to the standpipe pressure. Accordingly, the calibration technique and model may also take into account changes in rotational speed and standpipe pressure. In some cases, the ROP may also be used. In still other cases, other measurements or parameters (e.g., fluid viscosity, temperature, top drive pressure, motor pressure drop, etc.) may show correlations that can be used in developing the calibration model.

FIG. 7 is a flow chart of a method 764 for determining a mass of wellbore cuttings, according to at least one embodiment of the present disclosure. The power consumption of one or more shale shakers and/or the motors powering the shale shakers may be measured at 766. Using the measured power consumption, a mass of the cuttings and/or other cuttings properties and/or drilling fluid may be determined at 768. In some embodiments, the mass of the cuttings is measured over a period of time to determine a cumulative collected mass of cuttings. In some embodiments, the mass flow rate (e.g., in kg/min or other mass flow rate) may be determined. Further, the mass of the cuttings may be measured at 768 on a single shale shaker or, for multiple shale shakers.

FIG. 8 is a flow chart of a method 867 for controlling a drilling operation, according to at least one embodiment of the present disclosure. As discussed above with reference to FIG. 7, the power consumption of one or more shale shakers and/or the motors powering the shale shakers may be measured at 866. Using the measured power consumption, a mass of the cuttings and/or other cuttings properties and/or drilling fluid may be determined at 868. In some embodiments, the mass of the cuttings is measured over a period of time to determine a cumulative collected mass of cuttings. In some embodiments, the mass flow rate (e.g., in kg/min or other mass flow rate) may be determined. At 870, the mass of cuttings may be compared to an expected mass of cuttings at 870. As discussed herein, the expected mass of cuttings may be determined using the geometry of the wellbore and/or the formation being drilled through.

If the determined mass of the cuttings is not equal to the expected mass of the cuttings, then a control measure may be performed at 872. As discussed herein, control measures may be any drilling action taken. For example, a control measure may be to simply wait for more of the cuttings to be flushed out of the wellbore. In some examples, a control measure may be to perform one or more downhole drilling activities, change a density and/or viscosity of the drilling fluid to float more cuttings out of the wellbore. In some examples, a control measure may be to change a rotational rate of the drilling tool. In some examples, a control measure may be to change a weight on bit of the drilling tool. Any other control measure may be taken, including combinations of the foregoing.

After the control measure is taken, the method 867 may be repeated, and the power consumption of the one or more shale shakers may be measured. In some embodiments, the power consumption of the shale shakers may be continuously monitored, and the mass of cuttings continuously determined over a period of time.

If the determined mass of cuttings is equal to the expected mass of cuttings, then a drilling operation may be performed at 874. Any drilling operation may be performed, including adding sections of casing, grouting, plugging, fracking, drilling to advance a depth of the wellbore, reaming, casing cutting, adding a dogleg, tripping in/out of downhole tools, surveying, collecting other downhole measurements, downhole communications, flushing the hole, any other drilling operation, and combinations thereof.

INDUSTRIAL APPLICABILITY

This application relates to devices, systems, and methods for monitoring the conditions of a surface rig for downhole drilling. The power draw from a shale shaker that separates cuttings from drilling fluid may be used to determine the mass and/or volume of cuttings separated from the drilling fluid. In this manner, a drilling operator may have a quick and low-cost mechanism to monitor the amount and/or status of the cuttings removed from a wellbore. This may help the drilling operator to be more responsive to changes in drilling conditions, thereby saving time and money.

In accordance with embodiments of the present disclosure, detecting the state of the shaker by estimating cuttings flux/volume may enable state detection related to the lag between starting circulation or starting to drill rock and the time the cuttings come across the shakers. This may be dependent on various factors, as the time for cuttings to move out of the well and get to surface varies on the fluid properties, the cuttings dropping during connections, etc. This factor may also vary on the pipe rotational speed, and continuous measurement enabled by the power consumption measurement will enable enhancement of hole cleaning and wellbore risk reduction service monitoring, hole cleaning effectiveness, and wellbore stability. Further, by comparing measured and theoretical volumes of cuttings, early detection can be provided when there is inadequate hole cleaning (which could lead to stuck pipe) or when there are excess returns caused by wellbore instability/caving or formation damage. Early detection of these features also allows early remediation, minimization of off-bottom circulation time, and safety improvements. The drilling system may therefore have reduced non-productive time and higher ROP, which may be particularly beneficial in extended-reach drilling, highly deviated wells, or where there are difficult hole-cleaning conditions, unstable wells, or complex deepwater wells.

By way of example, the power data can be monitored continuously to provide a qualitative assessment that may be less than a quantitative accuracy of a cuttings flow meter, but it could characterize anything about the flux rate of the cuttings out of the well, even materials that are filtered out with a cuttings flow meter weight-based method. As a result, if cuttings are observed to be coming out in waves (as estimated by power consumption of the shaker), additional information can be inferred about hole cleaning efficiency, which could be tied back to flow rate or rotational speed control, for automated hole cleaning optimization. For instance, different states of cuttings can flux out of a high angle well, rather than a smooth, steady state flux, which would allow corresponding changes to account for the hole cleaning.

While measurements of power consumption and other operating parameters may occur at the surface, in some cases, there may be additional measurements from a downhole location. For instance, a downhole effective density or equivalent circulating density (ECD) measurement can average out the effect above/along a sensor-surface interval in the wellbore annulus. By adding downhole pressure measurements (e.g., at least two pressure measurements optionally a determined distance apart (5 ft. (1.5 m), 10 ft. (3.0 m), 25 ft. (7.6 m), 50 ft. (18.3 m), etc.), waves downhole could be seen that correlate to surface power waves.

During operation of the surface equipment, the power consumption of any one or even all shakers may be continuously monitored. The power consumption may be cross-calibrated with a computer vision system, a weight-based flow meter, or the like to integrate the shaker power measurement with the video/cuttings weight analysis. This may allow greater consistency. In some cases, cross-calibration is performed on fewer than all shakers where power monitoring is occurring. For instance, video, weight-based, or other secondary cuttings analysis may occur on one shaker that also has power consumption monitoring. On that shaker, the calibration model may continually be refined and verified, and the model may then be expanded to use with other shakers that do not have the secondary monitoring system. This may be particularly beneficial in some instances, as the power consumption modelling may be inexpensive and using a single secondary system may reduce overall costs.

While embodiments of the present disclosure have been discussed with reference to using power consumption to determine loading due to cuttings, other, similar embodiments may also be used for other purposes with respect to a shaker or other surface equipment. For instance, changes in total power consumption of the shakers may be measured over time rather than (or in addition to) continuous interpretation. For instance, such monitoring may be used to detect changes in power consumption which represent changes in the density of material coming out of the wellbore.

To further illustrate, if a pulse of cuttings come up out of the wellbore but the flow rate doesn't change much, that may be represented as a spike in power consumption that is indicative that the cuttings have just hit the shakers. A comparison of flow rate to power consumption could, therefore, act as a proxy for fluid density or fluid viscosity. Calibrating the measurements may therefore include monitoring fluid density, and then using concurrent flow rate and power consumption measurements to determine a relationship (which may be non-linear). Later measurements may then be used to estimate fluid density or viscosity in addition to, or in lieu of, cuttings volume by using the calibration model and measured flow rate and power consumption.

In some cases, by estimating the different densities/viscosities of the fluids flowing over the shakers (e.g., with power consumption measurements from a shaker, the power draw profile, or in other manners), displacement interface identification could be used for drilling fluid displacements, completions operations, cement jobs, or any other operation where a displacement fluid is used. For instance, cement jobs would benefit from rapid detection of spacer/cement on surface because the returned cement can harm the fluid and equipment. Instead of a mud engineer inspecting the return flow line at the wellhead prior to flow to the shakers, and optionally doing visual tests/ES/phenolphthalein with a jug to identify the interface and subsequent fluid, estimating the fluid density/viscosity change by having a measurable, distinct change in the fluid coming back, could in effect create an early warning/detection system for displacements that would allow the mud engineer to divert fluid faster and more accurately, minimizing interfaces and increasing the quality of fluid displaced into and out of the well, which can have significant costs operationally and in the clean-up/disposal section. The detection could also operate automatically to control diversion when fluid viscosity/density is detected. Notably, this could be done with either a qualitative or quantitative measurement. For instance, even without an accurate quantitative measurement, detecting notable changes to the determined density could significantly improve displacement performance/costs.

The fluid density/viscosity may be measured, particularly in cases where there are limited cuttings (e.g., flowing of a displacement fluid), which allows the same system to use multiple calibration models based on the type of operation. For instance, a first calibration model may be used for drilling, and a second calibration model may be used when flowing a displacement fluid. Indeed, different calibration models may also be used based on the type of drilling (e.g., straight drilling, underreaming, directional drilling, etc.), type of fluid used during drilling or displacement, and the like.

In another case where there may be no or limited cuttings or other solids coming up from the wellbore, other models and estimates may be used to infer something about the fluid rheology as it is tuned. For instance, if an additive is used to increase the viscosity of the mud, there may be a corresponding increase in shaker power consumption half an hour later, an hour later, etc. when the fluid has made the full downhole and return trip.

Increased fluid viscosity due either to treatment or increased low gravity solids (LGS) can make the fluid spend longer on a shaker screen than otherwise would be expected. This can result in higher fluid mass and higher power consumption. Lower fluid viscosity could correspondingly show reduced power consumption. Detecting these changes would be useful for a variety of operations, including to detect the “heartbeat” of the circulating system. As an example, if more viscosifier is added to the fluid, the expectation may not be to see that fluid back on surface for a half hour, a couple hours, or more. This increase in power consumption due to increased transit time on the shake screen may be unrelated to cuttings but could give us an idea when the treatment reaches the surface, and if this occurs early or late it enables alteration of a treatment schedule or regime accordingly.

By way of example, TRUVIS viscosifier can be added to VERSACLEAN mineral oil-based drilling fluid (both available from Schlumberger Limited) over two cycles. After one cycle, if a significantly more viscous fluid is detected by using power consumption on the shaker, the timing of the flow can be determined, and the operator can plan accordingly (e.g., to scale back on the material planned for the second cycle). In contrast, if the expected viscosity increase observed by monitoring power consumption occurs later than expected, an inference may be made that there was a downhole washout or other related issue so that investigation or remedial action can be taken. This may produce an overall “smart” system that uses either the qualitative or quantitative analysis for automated or machine-guided operations, which could reduce personnel at the rig site, leading to reduced costs and increased safety.

In another example, the distribution of fluid mass as a function of power consumption may be used to determine the proportion of total flow across each shaker, and that proportion can be linked to the frequency of screen changes in order to provide an estimated “time to screen change” factor. This may operate as a type of health monitoring system and the expected life can be provided, or an alarm can be generated to request an operator inspect the shaker set-up. In some cases, the system may automatically control operation, such as by generating a request for a replacement screen at a predetermined threshold health level, or when the expected life drops below a threshold.

Typically, in order to inspect/change screens, the shaker must be switched off, which by default increases the load on the other screens. By having a link between fluid distribution, shaker parameters, and time spent flowing (and optionally the flow rate), the screen maintenance process could largely or entirely be automated, or down-time of any particular shaker may be minimized. As a result, holes can be fixed faster and less strain will be placed on other shakers by not shutting down cooperating shakers so often or for as long. Even further, the power consumption “pattern” can be linked to screens with a hole and to those without. By knowing the expected power consumption in a group of shakers, changes in power consumption can be used to detect when a screen has holes in it by either a lower power consumption or an inconsistent power consumption as the fluid will be being lost through holes unexpectedly. The inconsistency of the power consumption may be evaluated on a screen-by-screen basis, such that certain fluxes may be expected due to minor and major flow surges, but would likely be represented at all screens, where one screen with hole may represent a different pattern.

In still another aspect, the power consumption may be used to detect screen blinding, even if the blinding occurs due to factors other than cuttings. For instance, LGS and/or high flow rates may cause screen blinding. Even if the mass of cuttings and LGS is low, then the mass of the fluid flowing across the screen could give an idea of the screens being blinded.

According to a further aspect, the power consumption can be monitored for differences based on where fluid is on the screen (with potential use of corresponding calibration models). For instance, shaker angles can be adjusted to have a beach about 66% of the way across the screen, which may produce a different power consumption or “signature” at high or even low flow rates than a screen that is totally covered and blind. Thus, measuring power draw may be used to estimate/detect screen blinding even without a potential correlation to cuttings mass.

Further examples of using power consumption may occur at other areas of a rig or on other surface equipment, and is not limited to use with shakers. Thus, power consumption for any number of types of equipment (e.g., pumps, agitators, draw works, etc.) may be monitored and used as proxy for other characteristics of interest.

For instance, for the mud pumps, the pump speed and the discharge pressure can be measured to provide an indication of the flow and the pressure to circulate fluid around the well. With a measure of the current draw and hence the power consumption, the efficiency of the pump can be estimated. Changes in the efficiency can be indicative of damage to the pump (or pump efficiency), density and solids content of the pumped fluid, or a change in other fluid characteristics (e.g., density, viscosity, or rheology). By tracking the changes in power consumption, long term changes in pump condition can be identified as well as transient changes in the pumped fluid. For instance, knowing when the fluid changes can therefore indicate a viscous sweep is being pumped. Knowing when the rheology of the drilling fluid changes allows detection, for example, when the driller pumps a sweep of high viscosity fluid to help clean the well. The standpipe pressure may change as the viscous sweep goes around the system (through the bit, up the annulus, etc.). Having the knowledge of when the sweep is launched can mitigate many false alarms from the pressure monitoring systems. The same is true when the mud density is changed, and all of which can provide insight for automated state estimation and alarm systems based on pressure. Similar processes for measuring power consumption may be used for boost pumps.

In another aspect, the current draw or other power consumption can be measured for the draw works and used as a proxy for the hook load. A second measurement from the active end of the sheaves could further bring options to correct for sheave friction, which can potentially provide a lower cost solution than a load cell on the draw works, particularly where some surface equipment already provides the power consumption for the draw works.

Another aspect is to use the power consumption of the active/reserve pit agitators as a proxy for mud viscosity. When mixing fluid that becomes too viscous, the pumps can lose prime and be difficult to fix and/or result in large downtime. Having an idea during treatment of how much power an agitator should consume for a particular viscosity at a given rotational speed, would allow modifying treatment. For instance, treatment could be slowed to avoid over-shooting the viscosity desired or at least to know how quickly the treatment is taking effect, which can lead to quicker deployment and save operational time and chemical treatment costs.

In some cases, monitoring the power consumption of mix pumps, agitators, or mud pump could also be used as an early warning system for a high-viscosity slug travelling down the drill string or of a lower temperature fluid from a reserve pit. If linked to hydraulic models or similar, the cold or thick fluid will cause an equivalent circulating density (ECD) spike, surging the well, when it exits the bit. Knowing this, the flow rate can be slowed temporarily to avoid an ECD shock until the slug either clears the low annular clearance section or surface fluid treatment is completed as a remediation step. Transit time down the string occurs quickly, and such automatic detection could more accurately and quickly detect such fluids as compared to human measurements.

In another example, power consumption measurements of a top drive may be used (optionally with a WOB sensor) to optimise acceleration/deceleration times while tripping. Acceleration/deceleration times can be based on an estimated distance or time factor and can easily represent 20 ft. (6 m) of a stand in a sub-maximum speed. These can be constant values based on the hydraulic models, but are not based on measured data. If rig power measurements are available, they can be used to accurately select acceleration/deceleration rates in real time that are flexible and dependent on the measurements, position, and conditions. These time changes may be minor on a stand-by-stand basis, but could potentially add to hours of savings in total tripping time.

The foregoing are illustrative, and countless opportunities are available by measuring power consumption at different locations on a rig or at other surface equipment. For instance, measurements at the draw works (e.g., power and current, acceleration of drum, etc,) can be used for the control of swab surge, optimization of trip time, minimization of forces on system, to characterize line properties and condition. Using this information, power/current can be correlated to find loads on drum to correlate and correct dead line tension, or drum acceleration can be integrated with line position. Speed profiles may also be set to interrogate different depths of the well for load and cuttings build up, or the like. The same speed profiles may also be used from the top drive to interrogate the location of tight spots.

In another example, block velocity or block height control may be monitored. Measurements may include the drum acceleration with drum velocity, the power to the draw works, and the dead line load. These measurements enable improved control of block velocity and block position, particularly at transitions between zones. The measurements also can integrate power, current speed, and acceleration to optimize the tripping time versus hole condition, pressures, load on the rig, load on the sheaves, fuel/power consumption, etc. Measurements may also enable identification of bed boundaries and detection of cuttings beds from improved load measurement from draw works power.

To make such interpretations, the tension in line can be determined from power, optionally with corrections for friction. Closed loop control may further be used using velocity, acceleration, and load for improved management in transition zones, and acceleration can be used to detect ROP changes.

As discussed in some detail herein, power (e.g., current draw) from a shaker can be used, and potentially the power of stirrers/agitators in mud tanks. This may be used to detect the interface between fluids during fluid swap out or roll over, or to detect changes in fluid density or viscosity. The estimation models can include or reflect changes as the fluid flowing over the shaker screens vary the drag force and hence the power drawn to drive the shaker. The power drawn by the stirrers can also be a function of the fluid depth and the fluid viscosity, and with a known depth, changes in power consumption can be interpreted as changes in the fluid properties.

When monitoring a top drive, the power/current can be a proxy for torque. Vibration (e.g., lateral, torsional, etc.) can also or alternatively be measured. These measurements can be used for a control system on torque, speed, and vibration/perturbation, and to detect dysfunction in the drill string. To do so, the controller can mitigate perturbation and integrate torque and torsional speed. Using speed modulation as in weight, there can be an attempt to get spatial resolution of issues. High frequency power/current measurements can also be used as a proxy for high frequency torque, and integrated with high frequency position and acceleration.

Motor efficiency may also be optimized with power measurements by monitoring motor power and motor/winding temperatures, speed, output, pressure, load, and the like, to the end of controlling the motor power, speed, and cooling. In particular, the measurements can be used for a motor load factor and to develop a cooling strategy to manage motor temperature and optimize efficiency.

In another example, boost and transfer pump performance is improved by optimizing boost and transfer pump performance (e.g., to mitigate dead heading, running dry, excessive wear, etc.). Measurements can include the power/current draw for pumps, and optionally discharge pressure. Boost pump transducers may fail when mud pump suction valves leak, and the measurements taken can be used to identify when the mud pumps have leaking valves from power signal noise The power measurement may be used as an indicator of the motor operation, and thus speed control.

Operations in lost zones may also be improved by using measurements such as block height, dead line load, power to the draw works, position, acceleration, top drive torque, and top drive power. Using such measurements, an analysis system can identify when drilling is entering a loss zone based on the drilling characteristics, and value can be added by knowing when exiting the loss/unconsolidated zone so that casing can be set. To use the measurements, rate of penetration optimization (ROPO), ROP or WOB with changepoint detection can be used to identify changes in formation. Where WOB is difficult to measure (e.g., under low weight), draw works power and deadline load can be used to derive WOB.

Further examples enhance loss detection with flow in measurements. Measurements may include mud pump speed and power, charge pump speed and power, fluid density and rheology, standpipe pressure, mud pump suction pressure, or any combination thereof. The flow in measurement may be measured by pump strokes; however, this may not account for changes in volumetric efficiency, so an improved flow measurement can be used to help with influx/efflux detection. The boost pump may be a centrifugal pump with a different flow curve relative to the mud pump, and integrating the power/speed with the boost pump pressure can be used to find the mud pump flow rate.

In a blind drilling scenario, flow rates, standpipe pressure, hook load, deadline, draw works current/power, top drive torque, top drive power/current, or combinations thereof may be used to, for instance, manage the drilling process, track bottomhole pressure, and monitor for influx. To do so, standpipe pressure and flow rate can be used to give a bottomhole pressure after allowance for BHA pressure drop. Weight of the string can be used to determine any change in buoyancy, and torque change can evaluate changes in friction, with the change in friction dynamics and acceleration of the top drive.

For fluid control, current to the top drive and mud pumps, the hook load, and standpipe pressure may be used to correlate changes in pump power and top drive as both operate at a constant speed. Accordingly, a change in pump pressure can correlate with a change in torque through motor pressure drop, which can be used to correct the standpipe pressure for ECD estimates, and therefore manage ECD and bottomhole pressure and fluid density.

To adjust drilling conditions and manage shallow hole drilling (e.g., speed and WOB), power to the draw works and top drive may be used, optionally with accelerations on blocks, draw works, and top drive. Using fast power for torque and WOB measurements, the drilling dysfunction can be evaluated. Accelerations can also be integrated. This may be used to detect when crossing a bed boundary, but otherwise adjusting drilling conditions can improve reliability and tool health by reducing wear.

Generally, equipment condition may also be monitored, including the condition of pumps, motors, top drives, draw works, etc. The power and current drawn by all motors may be measured, as may the output power (e.g., flow*pressure; load*speed; torque*speed, etc.). These measurements may be used to evaluate the efficiency or pseudo efficiency of the components and track changes to identify degradation or other issues. Changes in fluid, leaks in valves in a pump, bearing problems in a top drive, and sheave problems may all be detected with these evaluations.

According to aspects of the present disclosure, well construction, well production, or other processes can use power measurements (potentially in combination with other measurements) to infer process or operational parameters. Examples include cuttings exiting a wellbore, fluid pumping at a particular time, fluid density/viscosity, etc. Power measurements can include electrical power consumption—which may be direct power measurements or current measurements—being fed to electrical motors driving pumps, shale shakers, etc. The power measurements may act as a proxy to characterize other parameters of interest.

For instance, current drawn by motors on shale shakers can be correlated with cuttings loading. Electrical power drawn by a pump can change with pump efficiency, condition of the pump, fluid rheology, fluid density, and fluid solids content. By tracking the changes in this parameter long term changes in pump condition can be monitored, as well as transient changes in the pumped fluid.

Power consumption measurements for electrical devices on a rig may already be available, or may be measured directly, such as by measuring 3-phase current draw with a clamp-on device.

Measurement of the cutting discharge from the well can identify when there is a cuttings transport problems, identify when the well is clean and it is low risk to run the next casing, reducing non-productive time, and help to calibrate wellbore hydraulics models. By having a continuous analysis of the volume of the rock cuttings, a user may be able to establish a situation with regards to wellbore stability, drilling efficiency, shaker loading, shaker efficiency, or the like, and take responsive or corrective actions.

Knowing when the rheology of the drilling fluid changes allows detection, for example, when the driller pumps a sweep of high viscosity fluid to help clean the well. Having the knowledge of when the sweep is launched can mitigate false alarms from the pressure monitoring systems. The same is true for changes in fluid density or reduced fluid viscosity.

According to some embodiments, a quantitative analysis is performed using power consumption measurements in order to obtain a quantified value (e.g., cuttings volume, fluid density, fluid viscosity, etc.). In other embodiments, a qualitative analysis is performed for trends over time, comparison among two shakers, two pumps, comparison to a prior fluid, etc. In such qualitative analysis embodiments, the analysis may use an inferred value or directly use the power consumption measurements. Comparisons are generally made to other inferred conditions, rather than to a threshold power value, although a comparison to a threshold power consumption may be used in some embodiments.

Computing systems may be used in order to perform aspects of the embodiments disclosed herein. For instance, a computing system may be used during drilling, production, remediation, or other use of a wellbore, and various special-purpose computing systems (e.g., rig, shaker, pump, or other computerized systems) may be used to drill, produce, or otherwise operate the well. In the same or other embodiments, such rig or wellbore systems can include computing components to perform real-time processing during operation to calculate loadings, efficiency, and the like based on myriad factors, including observed power/current consumption of a particular surface or downhole tool. A suitable computing system may include one or more processors of varying core configurations (including multiple cores) and clock frequencies. Such processors may be operable to execute instructions, apply logic, etc. It will be appreciated that these functions may be provided by multiple processors or multiple cores on a single chip operating in parallel, in sequence, or communicably linked together. In at least one embodiment, one or more of the processors may include one or more GPU.

A computing system may also include memory, which may be or include one or more memory devices or computer-readable media of varying physical dimensions, accessibility, storage capacities, and the like. Such media can include flash drives, hard drives, disks, random access memory, etc., for storing data, such as images, files, and program instructions for execution by one or more processors. In an embodiment, such computer-readable media may be computer-readable storage media that stores instructions that, when executed by a processor, are configured to cause the processor (and the computing system) to perform operations. For example, execution of such instructions may cause the computing system to implement one or more portions or embodiments of the methods described herein.

A computing system may also include one or more network interfaces for communicating over wired or wireless media using protocols, such as Ethernet, wireless Ethernet, etc. The network interface(s) may include any hardware, applications, or other software, and may therefore include Ethernet adapters, wireless transceivers, PCI interfaces, serial network components, other components, or combinations thereof, for communicating over wired or wireless media. The wireless media may also be considered a type of computer-readable media, and more particularly computer-readable transmission media, which is distinct from the computer-readable storage media described herein, although computer-readable storage media and computer-readable transmission media may be communicatively linked.

The processor system may take a number of suitable forms, and may be a mobile device that includes one or more network interfaces for communication of information, a server, a client in communication with a server, the combination of one or more servers and one or more clients, a standalone computing system (e.g., a desktop or laptop), or the like. An example computing device may include a wireless network interface (e.g., operable via one or more IEEE 802.11 protocols, ETSI GSM, BLUETOOTH®, satellite, etc.). As an example, a computing device includes components such as a main processor, memory, a display, display graphics circuitry (e.g., optionally including touch and gesture circuitry), a SIM slot, audio/video circuitry, motion processing circuitry (e.g., accelerometer, gyroscope), wireless LAN circuitry, smart card circuitry, transmitter circuitry, GPS circuitry, a battery, and the like. In the case of a mobile device or a client, the computing device may be configured as a cell phone, a tablet, etc. As an example, methods of the present disclosure may be implemented (e.g., wholly or in part) using a mobile device, and a computing device may include one or more mobile devices.

A computing system may also include one or more peripheral interfaces, for communication with a display, projector, keyboards, mice, touchpads, sensors, other types of input or output peripherals, and the like. As an example, information may be input from a display (e.g., a touchscreen), output to a display, or both. As an example, information may be output to a projector, a laser device, a printer, etc. such that the information may be viewed. As an example, information may be output stereographically or holographically. As to a printer, consider a 2D or a 3D printer.

In some implementations, the components of computing system are not enclosed within a single enclosure or even located in close proximity to one another, but in other implementations, the components or other features may be provided in a single enclosure. As an example, a system may be a distributed environment, for example, a so-called “cloud” environment where various devices, components, etc. interact for purposes of data storage, communications, computing, etc. As an example, a method may be implemented in a distributed environment (e.g., wholly or in part as a cloud-based service).

Memory may be physically or logically arranged or configured to store data on one or more storage devices, which can include one or more file systems or databases in any suitable format. A storage device may also include one or more software programs containing interpretable or executable instructions for performing processes such as disclosed herein, or portions thereof. When requested by one or more processors, software programs or a portion thereof may be loaded from the storage devices into memory for execution by the processor(s).

Those skilled in the art will appreciate that the above-described componentry is merely one example of a hardware configuration, as a computing or processor system may include any type of hardware components, including any accompanying firmware or software, for performing the disclosed implementations. Such a system may also be implemented in part or in whole by electronic circuit components or processors, such as application-specific integrated circuits (ASICs) or field-programmable gate arrays (FPGAs).

The embodiments of the present disclosure have been described herein primarily with reference to using rig or other surface equipment power/current consumption measurements as proxies for other conditions, which enable control of, or alerts relating to, various operational parameters. For instance, shale shaker loading may be balanced, shaker screen angles adjusted, shaker screens cleaned, pump operation optimized or pump health evaluated, hook load determined, fluid type detected and diverted, and the like. In other embodiments, systems of the present disclosure may be used outside a wellbore or other downhole environment used for the exploration or production of natural resources. For instance, power consumption measurement and condition estimation systems may be used for the placement of utility lines. Accordingly, the terms “wellbore,” “borehole” and the like should not be interpreted to limit tools, systems, assemblies, or methods of the present disclosure to any particular industry, field, or environment.

One or more specific embodiments of the present disclosure are described herein. These described embodiments are examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, not all features of an actual embodiment may be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous embodiment-specific decisions will be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one embodiment to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. For example, any element described in relation to an embodiment herein may be combinable with any element of any other embodiment described herein. Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about” or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure. A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result. The stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value.

A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words “means for” or “step for” appear together with an associated function. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.

The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that is within standard manufacturing or process tolerances, or which still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 5% of, within less than 1% of, within less than 0.1% of, and within less than 0.01% of a stated amount. Further, it should be understood that any directions or reference frames in the preceding description are merely relative directions or movements. For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements. The term “may” is used to describe specific embodiments that include the recited feature or function, but reflect that such feature or function is optional and not included in other embodiments within the scope of this disclosure.

Various features are described herein in alternative format in order to emphasize that features may be combined in any number of combinations. Each feature should be considered to be combinable with each other feature unless such features are mutually exclusive. The term “or” as used herein is not exclusive unless the contrary is clearly expressed. For instance, having A or B encompasses A alone, B alone, or the combination of A and B. In contrast, having only A or B encompasses A alone or B alone, but not the combination of A or B. Even if not expressly recited in multiple independent form, the description provides support for each claim being combined with each other claim (or any combination of other claims).

The present disclosure may be embodied in other specific forms without departing from its spirit or characteristics. The described embodiments are to be considered as illustrative and not restrictive. The scope of the disclosure is, therefore, indicated by the appended claims rather than by the foregoing description. Changes that come within the meaning and range of equivalency of the claims are to be embraced within their scope. 

What is claimed is:
 1. A method for inferring cuttings properties from a wellbore, comprising: performing a drilling operation; separating cuttings from drilling fluid using a separation element; monitoring power consumed by the separation element while separating the cuttings; and using the power consumed by the separation element, inferring one or more properties of the cuttings.
 2. The method of claim 1, wherein separating the cuttings includes separating the cuttings from the drilling fluid using a shale shaker.
 3. The method of claim 1, wherein inferring the one or more properties of cuttings includes inferring a mass of the cuttings.
 4. The method of claim 1, further comprising: in response to inferring the one or more properties of the cuttings, controlling a surface or downhole parameter.
 5. The method of claim 4, wherein controlling the surface or downhole parameter includes at least one of balancing cuttings load between multiple separation elements, balancing fluid volume between multiple separation elements, balancing power consumption between multiple separation elements, changing an oscillation of the separation element, changing a screen angle of the separation element, fluid flushing a screen of the separation elements, changing weight-on-bit, changing rotational speed, changing fluid flow rate, changing fluid density, changing drill pipe acceleration or deceleration during tripping, diverting fluid from the separation element, changing a fluid treatment plan, or generating an alarm.
 6. The method of claim 1, wherein inferring the one or more properties of the cuttings includes using a calibration model.
 7. The method of claim 6, wherein the calibration model is based at least partially on at least one of cuttings mass to power consumption, power consumption without cuttings, power consumption before fluid treatment, screen angle, screen beach, fluid viscosity, fluid density, or fluid flow rate.
 8. The method of claim 1, wherein the separation element is a shale shaker and the one or more properties includes a cuttings mass, the method further comprising: measuring cuttings mass using a mass-based cuttings flow meter or cuttings volume machine vision system; and cross-correlating the measured cuttings mass with the power consumed by the shale shaker.
 9. A system for inferring operational parameters at a wellsite, comprising: a drilling system configured to perform drilling activities that generate cuttings; a shale shaker; a motor powering the shale shaker; and a processor and memory, the memory including instructions which, when accessed by the processor, cause the processor to: measure a power consumption of the motor while the shale shaker separates the cuttings from drilling fluid; and based on the power consumption of the motor, determine a mass of cuttings separated by the shale shaker.
 10. The system of claim 9, wherein the instructions further cause the processor to compare the mass of the cuttings to an expected mass of cuttings.
 11. The system of claim 10, wherein the instructions further cause the processor to determine the expected mass of cuttings based on at least one of wellbore diameter, section length, or formation type.
 12. The system of claim 10, wherein, when the mass of the cuttings is less than the expected mass of cuttings, the instructions further cause the processor to instruct the drilling system to change a drilling parameter.
 13. The system of claim 10, wherein, when the mass of cuttings is greater than the expected mass of cuttings, the instructions further cause the processor to identify whether the mass of cuttings is greater than the expected mass of cuttings due to a difference in density of the cuttings.
 14. The system of claim 10, wherein measuring the power consumption includes measuring a current draw of the motor.
 15. A method for inferring cuttings properties from a wellbore, comprising: measuring a first power consumption of one or more shale shakers with a known mass and density of cuttings; measuring a second power consumption of the one or more shale shakers with wellbore cuttings from a wellbore; and based on the first power consumption and the second power consumption, determining a wellbore mass of the wellbore cuttings.
 16. The method of claim 15, wherein measuring the first power consumption includes measuring the first power consumption based on a known drilling fluid density, and further comprising determining a fluid density of drilling fluid with the wellbore cuttings.
 17. The method of claim 15, further comprising, based on the wellbore mass of the wellbore cuttings, determining whether there are cuttings remaining in the wellbore.
 18. The method of claim 17, wherein, when there are cuttings remaining in the wellbore, further comprising taking a control measure that flushes out cuttings remaining in the wellbore.
 19. The method of claim 15, wherein the one or more shale shakers includes a first shale shaker and a second shale shaker and determining the wellbore mass of the wellbore cuttings includes determining a first wellbore mass associated with the first shale shaker and a second wellbore mass associated with the second shale shaker.
 20. The method of claim 19, wherein, when the first wellbore mass is different than the second wellbore mass, applying a control measure that balances the first wellbore mass with the second wellbore mass. 